The invention relates generally to oil and gas wells. More particularly, the invention relates to systems and methods for producing hydrocarbon gas from a formation that is also producing liquids.
Geological formations that yield gas also produce liquids that accumulate at the bottom of the wellbore. In general, the liquids comprise hydrocarbon condensate (e.g., relatively light gravity oil) and interstitial water from the reservoir. The liquids accumulate in the wellbore in two ways—as single phase liquids that migrate into the wellbore from the surrounding reservoir, and as condensing liquids that fall back into the wellbore during production of the gas. The condensing liquids actually enter the wellbore as vapors; however, as they travel up the wellbore, their temperatures drop below the respective dew points and they change phase into liquid condensate.
In some hydrocarbon producing wells that produce both gas and liquid, the formation gas pressure and volumetric flow rate are sufficient to lift the liquids to the surface. In such wells, liquids do not accumulate but are instead moved up and out of the wellbore by the velocity of the gas stream. However, in wells where the gas does not provide sufficient transport energy to lift liquids out of the well (i.e., the formation gas pressure and volumetric flow rate are not sufficient to lift liquids to the surface), the liquids accumulate in the wellbore.
For example, referring now to FIG. 1, a conventional system 10 for producing hydrocarbons from a well 20 is shown. Well 20 includes a wellbore 26 that extends through a subterranean formation 30 along a longitudinal axis 17. System 10 generally includes a wellhead 13 at the upper end of the wellbore 26, a production tree 12 mounted to wellhead 13, a primary conductor 21 extending from wellhead 13 into wellbore 26, a casing string (“casing”) 22 coupled to wellhead 13 and extending concentrically through primary conductor 21 into wellbore 26, and a liquid tubing string 50 coupled to wellhead 13 and extending through casing 22 into wellbore 26 to a depth H50. An annulus 27 is formed between string 50 and casing 22. A fluid flow mechanism or pump 60 is disposed within string 50 and is configured to induce a flow of fluids from wellbore 26 to surface 15 through tubing string 50. In this embodiment pump 60 is a pumpjack that comprises a plunger disposed within string 50 that is actuated (e.g., reciprocated) within string 50 by a surface mechanism 62 to draw fluids to the surface 15 through string 50. Tree 12 includes a plurality of valves 11 configured to regulate and control the flow of fluids into and out of wellbore 26 during production operations.
During operation, formation fluids (e.g., gas, oil, condensate, water, etc.) flow into the wellbore 26 from a production zone 32 of formation 30 via perforations 24 in casing 22. Thereafter, the produced fluids flow to the surface 15 through the annulus 27. In most cases, the production zone 32 initially produces gas to the surface 15 through annulus 27 with sufficient pressure and volumetric flow rate to lift liquids that enter wellbore 26 from zone 32 through perforations 24. However, over time, the pressure and volumetric flow rate of the gas decreases until it is no longer capable of lifting the liquids that enter wellbore 26 to the surface 15. At some point, the gas velocities drop below the “critical velocity”, which is minimum velocity required to carry a droplet of water to the surface 15. As time progresses, droplets of liquid accumulate in the bottom of the wellbore, thereby forming a column 70 of liquid having a height H70. This column 70 of accumulated liquids imposes a back-pressure on the formation 30 that begins to restrict the flow of gas into wellbore 26, thereby detrimentally affecting the production capacity of the well 20. Consequently, once the liquids are no longer lifted to the surface with the produced gas, the well 20 will eventually become “loaded” as the liquid hydrostatic head pressure begins to overpower the lifting action of the gas flow, at which point the well is “killed” or “shuts itself in.”
To maintain and continue production from well 20, operators typically, among other things, engage in artificial lift techniques or processes to remove the accumulated liquids from the wellbore to restore the flow of gas from the formation into the wellbore and ultimately to the surface. For example, in the embodiment shown in FIG. 1, pump 60 is engaged to draw out liquids from wellbore 26 in order to lower or maintain the height H70 of column 70 to ensure adequate production from well 20 through annulus 27. The process for removing such accumulated liquids from a wellbore is commonly referred to as “deliquification” or in some cases “dewatering”.